In situ combustion with a mobile fluid zone

ABSTRACT

A process for hydrocarbon recovery from an oil sands reservoir having a mobile fluid zone above a bitumen zone. The process includes generating, in the bitumen zone a mobilized and through a mobility enhancing process. The process also includes recovering at least some of the original oil-in-place and injecting an oxidizing gas through an oxidizing gas injection well into the reservoir to support in situ combustion in the reservoir. The process includes generating fluid communication between the mobile fluid zone and the mobilized zone and recovering hydrocarbons mobilized by the in situ combustion using a hydrocarbon production well that is in fluid communication with the mobile fluid zone and the mobilized zone.

INCORPORATION BY REFERENCE TO ANY PRIORITY APPLICATIONS

Any and all applications for which a foreign or domestic priority claimis identified in the Application Data Sheet as filed with the presentapplication are hereby incorporated by reference under 37 CFR 1.57. Thisapplication claims the benefit of U.S. Provisional Application No.61/845,720, filed Jul. 12, 2013, entitled IN SITU COMBUSTION WITH AMOBILE FLUID ZONE, the entire contents of which are herein incorporatedby reference.

FIELD

The present disclosure relates to methods for recovery of viscoushydrocarbons from oil sands deposits using in situ combustion.

BACKGROUND

A variety of processes are used to recover viscous hydrocarbons, such asheavy oils and bitumen, from oil sands deposits. Extensive deposits ofviscous hydrocarbons exist around the world, including large deposits inthe Northern Alberta oil sands, that are not susceptible to standard oilwell production technologies. One problem associated with producinghydrocarbons from such deposits is that the hydrocarbons are too viscousto flow at commercially relevant rates at the temperatures and pressurespresent in the reservoir.

In some cases, such deposits are mined using open-pit mining techniquesto extract hydrocarbon-bearing material for later processing to extractthe hydrocarbons. Alternatively, thermal techniques may be used to heatthe oil sands reservoir to mobilize the hydrocarbons and produce theheated, mobilized hydrocarbons from wells.

One thermal method of recovering viscous hydrocarbons using twovertically spaced horizontal wells is known as steam-assisted gravitydrainage (SAGD). Various embodiments of the SAGD process are describedin Canadian Patent No. 1,304,287 and corresponding U.S. Pat. No.4,344,485. In the SAGD process, steam is pumped through an upper,horizontal, injection well into a viscous hydrocarbon reservoir whilemobilized hydrocarbons are produced from a lower, parallel, horizontal,production well that is vertically spaced and near the injection well.The injection and production wells are located close to the bottom ofthe hydrocarbon deposit to collect the hydrocarbons that flow toward thebottom.

The SAGD process is believed to work as follows. The injected steaminitially mobilizes the hydrocarbons to create a steam chamber in thereservoir around and above the horizontal injection well. The term“steam chamber” is utilized to refer to the volume of the reservoir thatis saturated with injected steam and from which mobilized oil has atleast partially drained. As the steam chamber expands upwardly andlaterally from the injection well, viscous hydrocarbons in the reservoirare heated and mobilized, in particular, at the margins of the steamchamber where the steam condenses and heats the viscous hydrocarbons bythermal conduction. The mobilized hydrocarbons and aqueous condensatedrain, under the effects of gravity, toward the bottom of the steamchamber, where the production well is located. The mobilizedhydrocarbons are collected and produced from the production well. Therate of steam injection and the rate of hydrocarbon production may bemodulated to control the growth of the steam chamber and ensure that theproduction well remains located at the bottom of the steam chamber in anappropriate position to collect mobilized hydrocarbons.

In Situ Combustion (ISC) may be utilized to recover hydrocarbons fromunderground oil sands reservoirs. ISC includes the injection of anoxidizing gas into the porous rock of a hydrocarbon-containing reservoirto ignite and support combustion of the hydrocarbons around thewellbore. ISC may be initiated using an artificial igniter such as adownhole heater or by pre-conditioning the formation around thewellbores and promoting spontaneous ignition. The ISC process, alsoknown as fire flooding or fireflood, is sustained and the ISC fire frontmoves due to the continuous injection of the oxidizing gas. The heatgenerated by burning the heavy hydrocarbons in place produceshydrocarbon cracking, vaporization of light hydrocarbons and reservoirwater in addition to the deposition of heavier hydrocarbons known ascoke. As the fire moves, the burning front pushes a mixture of hotcombustion gases, steam, and hot water, which in turn reduces oilviscosity and the oil moves toward the production well. Additionally,the light hydrocarbons and the steam move ahead of the burning front,condensing into liquids, facilitating miscible displacement and hotwaterflooding, which contribute to the recovery of hydrocarbons.

Canadian Patent 2,096,034 to Kisman et al. and U.S. Pat. No. 5,211,230to Ostapovich et al. disclose a method of in situ combustion for therecovery of hydrocarbons from underground reservoirs, sometimes referredto as Combustion Split production Horizontal well Process (COSH) orCombustion Overhead Gravity Drainage (COGD). The disclosed processesinclude gravity drainage to a basal horizontal well in a combustionprocess. A horizontal production well is located in the lower portion ofthe reservoir. A vertical injection and one or more vertical vent wellsare provided in the upper portion of the reservoir. Oxygen-enriched gasis injected down the injector well and ignited in the upper portion ofthe reservoir to create a combustion zone that reduces viscosity of oilin the reservoir as the combustion zone advances downwardly toward thehorizontal production well. The reduced-viscosity oil drains into thehorizontal production well under the force of gravity.

Canadian Patent 2,678,347 to Bailey discloses a pre-ignition heat cycle(PIHC) using cyclic steam injection and steam flood methods that improvethe recovery of viscous hydrocarbons from a subterranean reservoir usingan overhead in situ combustion process, referred to as combustionoverhead gravity drainage (COGD). Bailey discloses a method where thereservoir well network includes one or more injection wells and one ormore vent wells located in the top portion of the reservoir, and wherethe horizontal drain is located in the bottom portion of the reservoir.

The use of ISC as a follow up process to SAGD is disclosed in CanadianPatent 2,594,414 to Chhina et al. The disclosed hydrocarbon recoveryprocesses may be utilized in oil sands reservoirs. Chhina discloses aprocess where a former steam injection well, used during the precedingSAGD recovery process, is used as an oxidizing gas injection well andwhere another former steam injection well, adjacent to the oxidizing gasinjection well, is converted into a combustion gas production well. Thisresults in the horizontal hydrocarbon production well being locatedbelow the horizontal oxidizing gas injection well and at least onecombustion gas production well being spaced from the injection well by adistance that is greater than the spacing between hydrocarbon productionwell and the oxidizing gas injection well. Since the process disclosedby Chhina uses at least two wells pairs, ISC is initiated after theproduction well is sufficiently depleted of hydrocarbons to establishcommunication between the two well pairs.

Oil sands deposits may exist substantially in isolation, or may alsoinclude hydraulically contiguous mobile fluid zones that have relativelylow bitumen saturation, for example they may have significantsaturations of gas, water, or both. In such deposits, these mobile fluidzones can act as “thief zones” and have one or more undesirable effectson recovery methods. For example, oil sands deposits sometimes have amobile fluid zone above the bitumen or heavy oils. In such deposits, themobile fluid zone can have a significant saturation of gas which acts asthe “thief zone” and when recovering the bitumen or heavy oils using asteam-based recovery process, a pressure in the gas zone that is lowerthan the steam pressure used in the recovery may be detrimental to therecovery since a flow of steam into the thief zone can lead to steamloss. As the steam chamber approaches the gas zone, and if the steampressure is kept higher than the gas zone pressure, steam and possiblysome of the oil may be pushed into the gas zone. Recovery of naturalgas, in association with recovery of the bitumen or heavy oils, couldalso lower reservoir pressure, thereby reducing oil recovery, and mayresult in the recovery of oil being economically prohibitive. None of CA1,304,287, U.S. Pat. No. 4,344,485, CA 2,096,034, U.S. Pat. No.5,211,230, or CA 2,594,414 teach recovery of heavy oil from reservoirshaving a gas zone.

Canadian Patent Application No. 2,594,413, titled “In situ Combustion inGas Over Bitumen Formations”, relates to heavy oil recovery fromreservoirs having a gas zone. In the disclosed process, air is injectedinto a gas zone which overlies an oil sand, in situ combustion isinitiated within the gas zone, and the resulting combustion gaseshorizontally displace the natural gas to nearby production wells forrecovery. The gas zone may be in pressure communication with the heavyoil and combustion gases may re-pressurize the natural gas reservoir,which may facilitate the recovery of the heavy oil using SAGD.

Canadian Patent Application No. 2,692,204 to Sanmiguel et al. (2010)titled “Gas-Cap Air Injection for Thermal Oil Recovery”, relates toheavy oil recovery from reservoirs having a gas zone. The disclosedprocess produces bitumen or heavy oil from a subsurface oil sandsreservoir that is in fluid communication with an overlying gas zone. Themethod includes: providing an in situ combustion process in theoverlying gas zone to create or expand a combustion front within theoverlying gas zone, providing a thermal recovery process in the oilsands reservoir to create or expand a rising hot zone within the oilsands reservoir, and selectively operating the thermal recovery processor the in situ combustion process or both such that the rising hot zonedoes not intersect the overlying gas zone until the combustion front hasmoved beyond that portion of the overlying gas zone at the intersection.As noted on page 6 of CA 2,692,204, “If the thermal recovery processoccurs early and the rising heated fluid . . . enters the gas zone 30before the combustion front 90 has passed . . . the in situ combustionprocess within the gas zone 30 will be compromised or at leastnegatively impacted.”

U.S. Patent Applications No. 20120205096A1 and 20120205127A1 teach amethod for displacing water from a porous geological formation wherepressurized gas is injected into a zone and barrier wells are operatedto achieve a hydraulic pressure barrier surrounding the zone. The gasdisplaces water downward within the zone such that water is produced atthe water production wells.

SUMMARY

It is an object of the present disclosure to obviate or mitigate atleast one disadvantage of previous processes that relate to heavy oilrecovery from reservoirs having a mobile fluid zone above a bitumenzone.

According to one aspect, there is provided a process that includes:generating, in the bitumen zone and through a mobility enhancingprocess, a mobilized zone by recovering at least some of the originaloil-in-place; injecting an oxidizing gas through an oxidizing gasinjection well into the reservoir to support in situ combustion in thereservoir; generating fluid communication between the mobile fluid zoneand the mobilized zone; and recovering hydrocarbons mobilized by the insitu combustion using a hydrocarbon production well that is in fluidcommunication with the mobile fluid zone and the mobilized zone, the insitu combustion propagating at least in the mobilized zone.

The mobility enhancing process may be a steam-assisted hydrocarbonrecovery process, such as steam-assisted gravity drainage.

The mobility enhancing process may generate the fluid communicationbetween the mobile fluid zone and the mobilized zone. Alternatively, themobilized zone and the mobile fluid zone may not be in fluidcommunication before the in situ combustion process is initiated, andthe in situ combustion may generate the fluid communication between themobile fluid zone and the mobilized zone.

The process may further include producing combustion gases through acombustion gas production well. The hydrocarbon production well and thecombustion gas production well may be a generally horizontal well pair.The generally horizontal well pair may be used to generate the mobilizedzone through the mobility enhancing process.

Alternatively, the hydrocarbon production well and the oxidizing gasinjection well may be a generally horizontal well pair. The generallyhorizontal well pair may be used to generate the mobilized zone throughthe mobility enhancing process. The process may further includeproducing combustion gases through a combustion gas production well. Thecombustion gas production well may be a former mobility enhancingprocess well that is in gaseous communication with the oxidizing gasinjection well.

The oxidizing gas may be injected continuously or may be injectedintermittently.

Water may be injected in addition to the oxidizing gas.

The mobile fluid zone may be a gas zone. The oxidizing gas may beinjected into the gas zone or into the mobilized zone. The in situcombustion may propagate through the mobilized zone and through themobile fluid zone.

Alternatively, mobile fluid zone may be a water zone. The oxidizing gasmay be injected into the mobilized zone. The in situ combustion maygenerate steam from water in the water zone and the generated steam mayaid in the mobilization of hydrocarbons in the reservoir.

According to another aspect, there is provided a process for hydrocarbonrecovery from an oil sands reservoir having a gas zone above a bitumenzone. The process includes: utilizing a generally horizontal well pairto generate, through steam-assisted gravity drainage, a steam chamber inthe bitumen zone that is in gaseous communication with the gas zone. Thegenerally horizontal well pair includes: a generally horizontal segmentof a hydrocarbon production well, and a generally horizontal segment ofa steam injection well. The process includes injecting an oxidizing gasinto the gas zone through an oxidizing gas injection well that includesan oxidizing gas injection segment. The oxidizing gas supports in situcombustion in the reservoir and the in situ combustion propagates atleast in the steam chamber. The process further includes recoveringhydrocarbons mobilized by the in situ combustion using the hydrocarbonproduction well; and producing combustion gas through the steaminjection well. The generally horizontal segment of the steam injectionwell is disposed generally parallel to and spaced vertically above thehorizontal segment of the hydrocarbon production well, and the injectionsegment of the oxidizing gas injection well is spaced generally abovethe segment of the hydrocarbon production well and generally above thesegment of the steam injection well.

According to a further aspect, there is provided a process forhydrocarbon recovery from an oil sands reservoir having a water zoneabove a bitumen zone. The process includes: generating, in the bitumenzone and through steam-assisted gravity drainage, a steam chamber in thebitumen zone that is in fluid communication with the water zone;injecting an oxidizing gas through an oxidizing gas injection well intothe steam chamber to support in situ combustion in the reservoir and thein situ combustion propagating at least in the steam chamber; generatingsteam by heating water in the water zone through the in situ combustion,the generated steam aiding in mobilizing hydrocarbons in the reservoir;and recovering hydrocarbons mobilized by the in situ combustion using ahydrocarbon production well that is in fluid communication with thewater zone and the steam chamber.

Other aspects and features of the present disclosure will becomeapparent to those ordinarily skilled in the art upon review of thefollowing description of specific embodiments in conjunction with theaccompanying figures.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present disclosure will now be described, by way ofexample only, with reference to the attached Figures. The patent orapplication file contains at least one drawing executed in color. Copiesof this patent or patent application publication with color drawing(s)will be provided by the Office upon request and payment of the necessaryfee.

FIG. 1 is an illustration of an exemplary well configuration which maybe used in a process according to the present disclosure.

FIG. 2 is an illustration of another exemplary well configuration whichmay be used in a process according to the present disclosure.

FIG. 3 is an illustration of yet another exemplary well configurationwhich may be used in a process according to the present disclosure.

FIG. 4 illustrates an exemplary well configuration used in a computersimulation model.

FIG. 5 shows a graph illustrating the cumulative oil and gas productionrates for the simulation model.

FIG. 6 illustrates the oil saturation profile at the start of thesimulation.

FIG. 7 illustrates the temperature profile after one month of SAGDoperation of the simulation.

FIG. 8 illustrates the temperature profile of the simulation model after8 months of air injection.

FIG. 9 illustrates the oil saturation in the simulation model after 8months of air injection.

FIG. 10 illustrates the mole fraction of oxygen in the gas phase after 8months of air injection.

FIG. 11 illustrates the temperature profile after 22 months of airinjection.

FIG. 12 illustrates the oil saturation in the simulation model after 82months of air injection.

FIG. 13 illustrates the mole fraction of oxygen in the simulation modelafter 88 months of air injection.

FIG. 14 illustrates the temperature profile in the simulation modelafter 88 months of air injection.

DETAILED DESCRIPTION

For simplicity and clarity of illustration, reference numerals may berepeated among the figures to indicate corresponding or analogouselements. Numerous details are set forth to provide an understanding ofthe examples described herein. The examples may be practiced withoutthese details. In other instances, well-known methods, procedures, andcomponents are not described in detail to avoid obscuring the examplesdescribed. The description is not to be considered as limited to thescope of the examples described herein.

Heavy oil recovery techniques, such as SAGD, create mobilized zones inan oil sands reservoir, from which at least some of the originaloil-in-place has been recovered. Steam injection methods such ascyclic-steam stimulation (CSS) and steam assisted gravity drainage(SAGD) are, to date, the most commercially successful in situ heavy oiland bitumen recovery methods. However, continued improvements andreduction in steam to oil ratio (SOR) are desirable. A mobilized zonecreated using a SAGD process may be considered to be a mobile zonechamber.

In situ combustion (ISC) has been used in combination with steam-basedrecovery to reduce the overall SOR. However, in viscous heavy oilreservoirs, such as oil sands reservoirs, the heavy oil lacks ofsufficient fluid mobility and inhibits the injection of the oxidizinggas into the reservoir at sufficiently high rate to create theconditions for ignition and propagation of a combustion front. That is,heavy oil reservoirs do not have enough fluid mobility for the heavyoils to be displaced when a gas expands into the heavy oil reservoir.

One advantage of the process according to the present disclosure, over aprocess that uses ISC in combination with a mobility enhancing recoveryprocess in a reservoir that does not include a mobile fluid zone, isthat the presently disclosed process can be initiated earlier due to thepresence of the mobile fluid zone above a bitumen zone. It is no longerrequired that the mobility enhancing recovery process reach a stage ofmaturity before switching to in situ combustion. This results in afaster process compared to reservoirs without a mobile fluid zone. Forcases where the mobilized zone is generated using a steam-based mobilityenhancing process, a faster switchover to in situ combustion may reducethe amount of water used to produce the same amount of hydrocarbons.

Within the context of the present disclosure, reference is made to zonesor regions, such as bitumen zones, gas zones, and water zones. It willbe understood by those skilled in the art that this does not requirethat the reservoir within a particular zone or region be saturated withthe recited component. For example, a “bitumen zone” may contain bothbitumen and water distributed throughout the porous structure. In aparticular example of a “bitumen zone”, in a virgin rich oil sand, thepores may be 80 percent saturated with bitumen and 20 percent saturatedwith connate water.

In the context of the present disclosure, a “mobile fluid zone” is azone with enough fluid mobility for at least some of the components ofthe zone to be displaced when a pressure differential is imposed intothe mobile fluid zone. Mobile fluid zones may be, for example: gas zonesand water zones. A mobile fluid zone may have less than 50% bitumensaturation. In an example, a mobile fluid zone may contain bitumen,water and gas distributed through the porous structure. In anotherexample of a mobile fluid zone, the pores may contain predominantly gaswith a relatively small bitumen saturation distributed throughout theporous medium. A mobile fluid zone may have sufficient hydrocarbons tosupport in situ combustion.

The present disclosure generally provides a process for hydrocarbonrecovery from an oil sands reservoir having a mobile fluid zone above abitumen zone. The process includes: generating, in the bitumen zone andthrough a mobility enhancing process, a mobilized zone by recovering atleast some of the original oil-in-place; injecting an oxidizing gasthrough an oxidizing gas injection well into the mobile fluid zone orinto the mobilized zone to support in situ combustion in the reservoir;generating fluid communication between the mobile fluid zone and themobilized zone; and recovering hydrocarbons mobilized by the in situcombustion using a hydrocarbon production well that is in fluidcommunication with the mobile fluid zone and the mobilized zone, the insitu combustion propagating at least in the mobilized zone.

The mobility enhancing process may be a steam-assisted hydrocarbonrecovery process, such as steam-assisted gravity drainage. As usedherein, the term “mobility enhancing process well” should be understoodto refer to a well which is used to provide a mobility enhancer, such asheat, solvent, or both, to promote the movement of the hydrocarbonstoward the production well. Examples of a mobility enhancer include:steam, hot water, methane, hydrocarbon solvents, a heat source, orcombinations thereof. An example of a steam-assisted hydrocarbonrecovery well pair includes: a SAGD well pair. An example of asteam-assisted hydrocarbon recovery well includes: cyclic-steamstimulation well. An example of a non-steam based recovery methodincludes: electromagnetic heating.

The fluid communication between the mobile fluid zone and the mobilizedzone may be generated by the mobility enhancing process before the insitu combustion. Alternatively, the in situ combustion may be startedwhen the mobilized zone and the mobile fluid zone are not in fluidcommunication, and the fluid communication between the mobile fluid zoneand the mobilized zone may be generated by the in situ combustion.

The in situ combustion propagates at least in the mobilized zone. Sincethe in situ combustion in the mobilized zone is fueled by residualhydrocarbons in the oil sands deposits, the hydrocarbons in the oilsands deposit may be un-depleted, or may be partially depleted prior tothe process disclosed herein.

The hydrocarbon production well may be a generally horizontal well, agenerally vertical well, or a generally inclined well. The hydrocarbonproduction well may have a combination of different segments which areindependently generally vertical, generally inclined, or generallyhorizontal. The hydrocarbon production well may be located anywhere influid communication with the mobilized zone. For example, thehydrocarbon production well may be close to the bottom of thehydrocarbon deposit to collect the mobilized hydrocarbons that flowtoward the bottom due to gravity.

The oxidizing gas injection well may be located such that an oxidizinggas injection segment is located in gaseous communication with themobilized zone. For example, the oxidizing gas injection segment may bein the mobilized zone, or may be in the mobile fluid zone if the mobilefluid zone is a gas zone.

The oxidizing gas injection well may be a generally horizontal well, agenerally vertical well, or a generally inclined well. The oxidizing gasinjection well may have a combination of different segments which areindependently generally vertical, generally inclined, or generallyhorizontal. The oxidizing gas injection well may be completed with oneor more discrete injection locations. In some examples, the oxidizinggas injection well injects the oxidizing gas along the length of agenerally horizontal production well. This may be accomplished, forexample, by using a generally horizontal oxidizing gas injection wellthat is parallel to a generally horizontal production well and that hasa plurality of discrete oxidizing gas injection locations; or by using aplurality of vertical oxidizing gas injection wells aligned along thelength of a generally horizontal production well.

Combustion gases generated from the in situ combustion may be producedthrough a combustion gas production well, or through the hydrocarbonproduction well. If a combustion gas production well is used, it may bea generally horizontal well, a generally vertical well, or a generallyinclined well. The combustion gas production well may have a combinationof different segments which are independently generally vertical,generally inclined, or generally horizontal. The combustion gasproduction well may be located in the mobile fluid zone, or in themobilized zone.

The hydrocarbon production well may be a well that is unrelated to thewell or wells used to generate the mobilized zone. For example, a singlewell may be used as a mobility enhancing process well to generate themobilized zone and a different well may be used as the hydrocarbonproduction well to recover hydrocarbons mobilized by the in situcombustion. In such an example, the mobility enhancing process well maybe a well used for cyclic steam stimulation.

Alternatively, the hydrocarbon production well may be the productionwell in a well or wells used to generate the mobilized zone. Forexample, a single well may be used to generate the mobilized zone, forexample using cyclic steam stimulation, and that same well may be usedas the hydrocarbon production well to recover hydrocarbons mobilized bythe in situ combustion. In another example, a well pair may be used togenerate the mobilized zone where: (1) the former hydrocarbon productionwell from the well pair may be used as the hydrocarbon production wellto recover the hydrocarbons mobilized by the in situ combustion, and (2)the former mobility enhancing process well from the well pair may beused as the oxidizing gas injection well or as the combustion gasproduction well.

In examples where the former hydrocarbon recovery well pair is agenerally horizontal well pair and the former mobility enhancing processwell is used as the combustion gas production well, the oxidizing gasinjection well may inject the oxidizing gas along the length of thegenerally horizontal well pair. This may be accomplished, for example,by using a generally horizontal oxidizing gas injection well that isparallel to the generally horizontal well pair and that has a pluralityof discrete oxidizing gas injection locations; or by using a pluralityof vertical oxidizing gas injection wells aligned along the length ofthe generally horizontal well pair.

In processes that use steam as the mobility enhancer, such as SAGD,steam is injected into the steam injection well to mobilize thehydrocarbons and create a steam chamber in the reservoir, around andabove the generally horizontal segment. It may be beneficial if theoxidizing gas injection segment is located generally above both thesteam injection well and the hydrocarbon production well. Wells havingsuch a configuration take advantage of gravity segregation between theoxidizing gas and the liquids, including the hydrocarbons. By virtue ofthe density difference between gases and liquids, the liquids, includingthe hydrocarbons, tend to accumulate in the lower portion of thechamber, inhibiting fingering of the oxidizing gas into the hydrocarbonproduction wells. The oxidizing gas is generally consumed at thecombustion front. Thus, travel of oxidizing gas ahead of the combustionfront, into a colder region of the chamber, is inhibited. This isbeneficial as travel of oxidizing gas ahead of the combustion front mayinduce low temperature oxidation reactions and cause blocking problemsin the reservoir. A “blocking problem” would be understood to refer tonon-mobile oil blocking the movement of oxidizing gases to thecombustion front.

It should be understood that an oxidizing gas injection well beingdisposed “generally vertically above” or “generally above” a steaminjection well refers to the injection segment of an oxidizing gasinjection well being less than 75° from a vertical line extendingthrough the steam injection well. In particular embodiments, theinjection segment of an oxidizing gas injection well is less than about60° from the vertical line. In preferred embodiments, the injectionsegment of an oxidizing gas injection well is less than about 45° fromthe vertical line. The terms “directly vertically above” and “directlyabove” refer to embodiments where the injection segment of an oxidizinggas injection well is less than about 5° from a vertical line extendingthrough the steam injection well. The terms would similarly denote thespatial relationship of any other two wells.

In processes that use steam as the mobility enhancer, such as SAGD,additional components may be added to the injected steam. For example:light hydrocarbons, such as C3 through C10 alkanes, may optionally beinjected with the steam. The volume of light hydrocarbons that areinjected is relatively small compared to the volume of steam injected.The addition of light hydrocarbons is referred to as a solvent-assistedprocess (SAP). SAGD and SAP processes are both examples of mobilityenhancing processes. The SAGD or SAP processes may also be augmented orenhanced by inclusion of other substances, such as: non-condensinggases, for example: nitrogen or oxygen; surfactants; steam additives; orany combination thereof. Viscous hydrocarbons in the bitumen zone areheated and mobilized and the mobilized hydrocarbons drain, under theeffects of gravity. The mobilized hydrocarbons are collected andproduced from the hydrocarbon production well.

A mobility enhancing process may be performed for a period of time untilthe mobilized zone is in fluid communication with the mobile fluid zone.When the mobility enhancing process is SAGD, this may be achieved byinjecting steam through a steam injection well and recovering oil untilthe steam chamber is in fluid communication with the mobile fluid zone.Sensors such as pressure and temperature sensors located in the steaminjection well, in the hydrocarbon production well, in the oxidizing gasinjection well, or any combination thereof, may be utilized to detectwhen the steam chamber is in fluid communication with the mobile fluidzone. Alternatively or additionally, observation wells drilled into thereservoir may be utilized to determine that the steam injected is influid communication with the mobile fluid zone. Steam front monitoringmay also be utilized to determine that the injected steam is in fluidcommunication with the mobile fluid zone. Sensors and monitoring methodsmay also be used when the mobility enhancing process is a process otherthan SAGD.

Prior to ignition to start ISC in the oxidizing gas injection well,steam may be injected into the oxidizing gas injection wellbore toremove liquid hydrocarbons surrounding the wellbore. This injected steamraises the temperature of part of the reservoir, for example, to about150° C. Alternatively, a volatile oil mixture may be added to theformation and then displaced by steam injection followed by injection ofa non-condensing gas, for example nitrogen. For example, steam may beinjected for about one day, followed by nitrogen injection for about oneday. The steam, or steam and subsequent nitrogen, is used to reduce theamount of combustible materials from the immediate vicinity of theoxidizing gas injection wellbore and thereby reduce high temperatureexposure and consequent damage to the steel.

ISC is carried out by injecting an oxidizing gas through the oxidizinggas injection well. The in situ combustion propagates at least in themobilized zone. The oxidizing gas may be injected continuously forcontinuous combustion, or may be injected intermittently. Combustion maybe initiated utilizing an artificial igniter, such as a downhole heater,or by using spontaneous ignition. The oxidizing gas that is injected maybe, for example, air, enriched air, diluted air, or any other suitablegas including oxygen. The in situ combustion may be managed to mobilizehydrocarbons in the heavy oil by controlling: the rate, the pressure, orboth of oxidizing gas injected through the oxidizing gas injection well;the rate, the pressure, or both of production of combustion gases fromthe former steam injection well; the rate, the pressure, or both ofhydrocarbon production from the hydrocarbon production well; or anycombination thereof.

Optionally, water may be injected in addition to the oxidizing gas. Forexample, water may be injected at the same time as, or in sequence with,the oxidizing gas. The water may be injected through the same well asthe oxidizing gas, or through separate wells. Injected water, wateralready present in the reservoir, or both may result in a wet combustionprocess and steam generation. The generated steam may facilitate theflow of heated hydrocarbons to the hydrocarbon production well since thegenerated steam promotes heat transfer in the oil sands reservoir.

In processes that use a former SAGD steam injection well as thecombustion gas production well, the oxidizing gas is injected throughthe oxidizing gas injection well and into the reservoir. The generatedcombustion gases are produced from the former steam injection well, nowthe combustion gas production well, since they are driven into thegenerally horizontal segment of the steam injection well. Thehydrocarbons that are mobilized as a result of the combustion processdrain to the generally horizontal segment and are recovered through thehydrocarbon production well. Thus, the steam injection well and thehydrocarbon production well utilized in the SAGD process are utilized inthis example of the process to collect the combustion gases and toproduce the mobilized hydrocarbons, respectively. In this way, the SAGDwell pair is advantageously re-utilized.

Infill producer wells, which may have been added as concurrentsupplements to the SAGD process, are not required for the ISC processbut may be used as hydrocarbon production wells.

A benefit to utilizing a combustion gas production well that is separatefrom a hydrocarbon production well, is that the hydrocarbons that areproduced are separated from the combustion gases downhole, therebyreducing the chance of oxidizing gas and combustion gases communicatingwith the hydrocarbon production well. That is, it reduces the chancethat oxidizing gases, combustion gases, or both will escape via thehydrocarbon production well. This reduction may result in the combustionfront being more easily controlled. This reduction may additionallyreduce high volumes of combustion gases flowing into the hydrocarbonproduction well, which could restrict the flow of hydrocarbons into thehydrocarbon production well. Corrosion of metals, such as well tubes,and other well apparatus, may be mitigated and surface facilities designmay be facilitated as the gases and hydrocarbons are substantiallyseparated downhole. Notwithstanding the desirability of collecting thesefluid streams at separate wells, it should be understood that the wellwhich collects the combustion gases may also produce some hydrocarbons.Correspondingly, the hydrocarbon production well may produce somecombustion gases.

The ISC process that is carried out, referred to as top-down in situcombustion, takes advantage of gravity segregation between the oxidizinggas and the liquids, including the hydrocarbons. By virtue of thedensity difference between gases and liquids, the liquids, including thehydrocarbons, tend to accumulate in the lower portion of the chamber,inhibiting fingering of the oxidizing gas into the hydrocarbonproduction wells. The oxidizing gas is generally consumed at thecombustion front. Thus, travel of oxidizing gas ahead of the combustionfront, into a colder region of the chamber, is inhibited. This isbeneficial as travel of oxidizing gas ahead of the combustion front mayinduce low temperature oxidation reactions and cause blocking problemsin the reservoir. A “blocking problem” would be understood to refer tonon-mobile oil blocking the movement of oxidizing gases to thecombustion front.

For reservoirs where the mobile fluid zone is a gas zone, the gas zonemay have sufficient hydrocarbons to support in situ combustion. The insitu combustion may be initiated once the mobilized zone is in gaseouscommunication with the gas zone, or may be initiated in order togenerate gaseous communication between the mobilized zone and the gaszone. The in situ combustion may propagate in both the mobilized zoneand in the gas zone. Since the in situ combustion in the gas zone isfueled by hydrocarbons within the gas zone, the gas zone may beun-depleted, or may be partially depleted prior to the process disclosedherein.

When the mobile fluid zone is a gas zone, the pressure in the gas zonemay be greater than, about the same as, or less than the pressure of thegasses in the mobilized zone. It may be desirable to operate themobility enhancing process at a pressure lower than the pressure of thegas in the gas zone in order to expedite gaseous communication betweenmobilized zone and the gas zone.

The oil sands deposit may have mobile fluid zones comprisingnon-combustible gases, such as air zones, that are formed as a result ofnatural depletion of the hydrocarbons. The oil sands deposits may havemobile fluid zones that been formed by displacing one mobile fluid withanother mobile fluid. For example a liquid, such as water, may bedisplaced from the mobile fluid zone using pressurized gas injected intothe mobile fluid zone. Specific examples of methods of formation of suchmobile fluid zones are described in U.S. Patent Applications No.20120205096A1 and 20120205127A1.

In processes that use injected steam as the mobility enhancer and themobile fluid zone is a gas zone, it may be preferable to drill theoxidizing gas injection well prior to the steam chamber being in gaseouscommunication with the oxidizing gas injection well in order to avoiddrilling through a high temperature, high pressure reservoir. Forexample, the oxidizing gas injection well may be drilled into the gaszone before the steam chamber is in gaseous communication with the gaszone. In another example, the oxidizing well may be drilled into aportion of the reservoir that becomes a part of the steam chamber.

For reservoirs where the mobile fluid zone is a water zone, the in situcombustion may be initiated once the mobilized zone is in fluidcommunication with the water zone. The in situ combustion may propagateprimarily in the mobilized zone and may produce steam through heatingwater in the water zone. The produced steam may aid in the mobilizationof hydrocarbons in the reservoir.

In one exemplary process according to the present disclosure, theprocess includes generating a steam chamber using a steam-assistedhydrocarbon recovery process, such as SAGD, in a bitumen zone that isbelow a gas zone. The generated steam chamber is in gaseouscommunication with the gas zone. Oxidizing gas is injected in the gaszone to support in situ combustion in the reservoir. The oxidizing gasis injected using an oxidizing gas injection well. In this example, theformer steam injection well used in the steam-assisted hydrocarbonrecovery process is used as the combustion gas production well, and theformer hydrocarbon production well used in the steam-assistedhydrocarbon recovery process is used as the hydrocarbon production wellfor the in situ combustion. The in situ combustion propagates at leastin the mobilized zone. In this example, the former steam injection welland the former hydrocarbon production well are a generally horizontalwell pair, and the oxidizing gas injection well is a generallyhorizontal well that injects the oxidizing gas along the length of thegenerally horizontal well pair through a plurality of discrete oxidizinggas injection locations.

In another exemplary process according to the present disclosure, theprocess includes generating a steam chamber using a steam-assistedhydrocarbon recovery process, such as SAGD, in a bitumen zone that isbelow a water zone. The generated steam chamber is in fluidcommunication with the water zone. Oxidizing gas is injected in thesteam chamber to support in situ combustion in the reservoir. Theoxidizing gas is injected using an oxidizing gas injection well. The insitu combustion propagates at least in the steam chamber. The in situcombustion may produce steam through heating the water in the waterzone. The produced steam may aid in the mobilization of hydrocarbons inthe water zone, in the mobilized zone, or both. In this example, theformer steam injection well used in the steam-assisted hydrocarbonrecovery process is used as the combustion gas production well, and theformer hydrocarbon production well used in the steam-assistedhydrocarbon recovery process is used as the hydrocarbon production wellfor the in situ combustion.

In still another example of a process according to the presentdisclosure, the mobile fluid zone is a gas zone and the process includesgenerating a mobilized zone through a mobility enhancing process, andinjecting an oxidizing gas through an oxidizing gas injection well intothe gas zone or into the mobilized zone, the oxidizing gas supporting insitu combustion in the reservoir. The process includes generatinggaseous communication between the gas zone and the generated mobilizedzone. The oxidizing gas is injected using a former mobility enhancingprocess well. Another former mobility enhancing process well that is ingaseous communication with the oxidizing gas injection well is used as acombustion gas production well. The in situ combustion propagates atleast in the mobilized zone. Hydrocarbons mobilized through the in situcombustion are removed from the bottom of the reservoir using the formerhydrocarbon production well used in the mobility enhancing process.Additional gas production wells may be drilled in the gas zone or in themobilized zone.

In yet another example of a process according to the present disclosure,where the mobile fluid zone is a gas zone, the process includes: using agenerally horizontal well pair to generate, through steam-assistedgravity drainage, a steam chamber that is in gaseous communication withthe gas zone, where the generally horizontal well pair includes: agenerally horizontal segment of a hydrocarbon production well, and agenerally horizontal segment of a steam injection well; injecting anoxidizing gas into the gas zone through an oxidizing gas injection wellincluding an oxidizing gas injection segment, the oxidizing gassupporting in situ combustion in the reservoir and the in situcombustion propagating at least in the steam chamber; recoveringhydrocarbons mobilized by the in situ combustion using the hydrocarbonproduction well; and producing combustion gas through the steaminjection well. In such an example, the generally horizontal segment ofthe steam injection well is disposed generally parallel to and spacedvertically above the horizontal segment of the hydrocarbon productionwell, and the injection segment of the oxidizing gas injection well isspaced generally above the segment of the hydrocarbon production welland generally above the segment of the steam injection well.

Although examples discussed above discuss a steam-assisted hydrocarbonrecovery process, and specifically SAGD, being carried out before insitu combustion, it should be understood that mobility enhancingprocesses other than steam-assisted recovery may be used. For example,hot water, methane, hydrocarbon solvents, a heat source, or combinationsthereof may alternatively be used to establish fluid communicationbetween the oxidizing gas injection well and the hydrocarbon recoverywell.

One specific example of a generally horizontal well pair which may beused in the process disclosed herein is illustrated in FIG. 1. Althoughthe illustration and corresponding discussion relates specifically toSAGD, it should be understood that other mobility enhancing processesmay be used and, accordingly, the discussed steam injection well may besubstituted with another “mobility enhancing process well” and thediscussed steam chamber would be a corresponding “mobilized zone”.Further, although the illustration and corresponding discussion relatesspecifically to gas zones located above the bitumen zone, it should beunderstood that the process would be applicable in reservoirs havingother mobile fluid zones.

As illustrated in FIG. 1, the hydrocarbon production well includes agenerally horizontal segment 10 that extends near the base or bottom ofthe bitumen zone. The steam injection well also includes a generallyhorizontal segment 16 that is disposed generally parallel to and isspaced generally vertically above the horizontal segment 10 of thehydrocarbon production well.

The oxidizing gas injection well 18 is located with the gas injectionsegment in the gas zone 20 such that the segment extends generallyparallel to the generally horizontal segments 16 of steam injectionwell. The illustration in FIG. 1 shows the reservoir before gaseouscommunication has been generated between the gas zone 20 and the steamchamber 22.

It would be understood that an oxidizing gas injection well couldprovide oxidizing gas to mobilize hydrocarbons that are produced throughmore than one hydrocarbon production well, as illustrated in FIG. 2. Theillustration in FIG. 2 shows the reservoir before gaseous communicationhas been generated between the gas zones 20 and the steam chambers 22.

It would also be understood that a plurality of well pairs may beutilized at spaced-apart locations in the reservoir and a plurality ofoxidizing gas injection wells may be utilized to provide oxidizing gasto mobilize hydrocarbons. It should be understood that it is notnecessary to match the number of oxidizing gas injection wells to thenumber of steam injections wells. For example, two oxidizing gasinjection wells may be used in combination with three steam injectionwell, as illustrated in FIG. 3. In this example, three SAGD well pairsand two oxidizing gas injection wells 18 located with the gas injectionsegment in the gas zone 20 such that the injection segment extendsgenerally parallel to the generally horizontal segments 16 of steaminjection well.

FIG. 3 illustrates the reservoir after gaseous communication has beengenerated between the gas zone 20 and the steam chambers 22. Asillustrated, the steam chamber on the left and the steam chamber in themiddle are both in direct gaseous communication with each other and arein direct gaseous communication with the gas zone. The steam chamber onthe right is in direct gaseous communication with the gas zone, and isin gaseous communication with the other two steam chambers through thegas zone.

EXAMPLES Example 1

A computer simulation was run to model an oil sands recovery processwhere two SAGD well pairs and one gas producer well were used to recoverhydrocarbons. In the simulation, the two oxidizing gas injection wellswere located directly vertically above the two SAGD well pairs and thegas producer well was located within the gas zone, equally laterallyspaced apart from the two SAGD well pairs.

The configuration is illustrated in FIG. 4.

FIG. 5 shows a graph illustrating the cumulative oil and gas productionrates for the simulation model.

FIG. 6 illustrates the oil saturation profile at the start of thesimulation (2000-01-01). Original oil saturation in the gas zone is 20%,gas saturation is 60% and connate water is 20%. The initial reservoirtemperature is 8° C.

FIG. 7 shows the temperature profile after one month of SAGD operation(2000-02-01). The reservoir has reached a maximum temperature of 170° C.and communication has been established between the mobilized zonescreated by the SAGD process and the overlying gas zone.

After one month of SAGD, the SAGD process is finalized and in situcombustion is instigated in the reservoir by injecting air into theoxidizing gas injection wells. The previous steam injector is shut inand the gas producer in the gas zone starts operating.

FIG. 8 shows the temperature profile at 2000-09-01 after 8 months of airinjection. The combustion front has been ignited and is propagatingtowards the hydrocarbon producing wells as indicated by the elevatedtemperature profile.

FIG. 9 shows the oil saturation in the simulation model at 2000-09-01.Oil saturation around the air injector is preferably zero when thecombustion front is initiated as the residual oil saturation is consumedas fuel during the in situ combustion process.

FIG. 10 shows the mole fraction of oxygen in the gas phase at2000-09-01. The oxygen has been consumed by the combustion process atthe vicinity of the oxidizing gas injection wells.

FIG. 11 shows the temperature profile at 2001-12-01. The combustionfront is advancing towards the gas producer and expanding both in thegas zone as well as in the heavy oil zone.

FIG. 12 shows the oil saturation for the simulation model at 2006-12-01.

FIG. 13 shows the mole fraction of oxygen for the simulation model at2007-06-01.

FIG. 14 shows the temperature profile for the simulation model at2007-06-01. The figures illustrate that the combustion front hasprogressed significantly into the heavy oil zone.

The described examples are to be considered in all respects only asillustrative and not restrictive. The scope of the claims should not belimited by the preferred embodiments set forth in the examples, butshould be given the broadest interpretation consistent with thedescription as a whole. All changes that come with meaning and range ofequivalency of the claims are to be embraced within their scope.

What is claimed is:
 1. A process for hydrocarbon recovery from an oilsands reservoir having a mobile fluid zone above a bitumen zone, theprocess comprising: generating, in the bitumen zone and through amobility enhancing process, a mobilized zone by recovering at least someof the original oil-in-place; injecting an oxidizing gas through anoxidizing gas injection well into the reservoir to support in situcombustion in the reservoir; generating fluid communication between themobile fluid zone and the mobilized zone; and recovering hydrocarbonsmobilized by the in situ combustion using a hydrocarbon production wellthat is in fluid communication with the mobile fluid zone and themobilized zone, the in situ combustion propagating at least in themobilized zone.
 2. The process according to claim 1, wherein themobility enhancing process is a steam-assisted hydrocarbon recoveryprocess.
 3. The process according to claim 2, wherein the steam-assistedhydrocarbon recovery process is steam-assisted gravity drainage.
 4. Theprocess according to claim 1, wherein the mobility enhancing processgenerates the fluid communication between the mobile fluid zone and themobilized zone.
 5. The process according to claim 1, wherein themobilized zone and the mobile fluid zone are not in fluid communicationbefore the in situ combustion process is initiated, and wherein the insitu combustion generates the fluid communication between the mobilefluid zone and the mobilized zone.
 6. The process according to claim 1,further comprising producing combustion gases through a combustion gasproduction well.
 7. The process according to claim 6, wherein thehydrocarbon production well and the combustion gas production well are agenerally horizontal well pair.
 8. The process according to claim 7,wherein the generally horizontal well pair is used to generate themobilized zone through the mobility enhancing process.
 9. The processaccording to claim 1, wherein the hydrocarbon production well and theoxidizing gas injection well are a generally horizontal well pair. 10.The process according to claim 9, wherein the generally horizontal wellpair is used to generate the mobilized zone through the mobilityenhancing process.
 11. The process according to claim 10, furthercomprising producing combustion gases through a combustion gasproduction well.
 12. The process according to claim 11, wherein thecombustion gas production well is a former mobility enhancing processwell that is in gaseous communication with the oxidizing gas injectionwell.
 13. The process according to claim 1, wherein the oxidizing gas isinjected continuously.
 14. The process according to claim 1, wherein theoxidizing gas is injected intermittently.
 15. The process according toclaim 1, wherein water is injected in addition to the oxidizing gas. 16.The process according to claim 1 wherein the mobile fluid zone is a gaszone.
 17. The process according to claim 16, wherein the oxidizing gasis injected into the gas zone.
 18. The process according to claim 16,wherein the oxidizing gas is injected into the mobilized zone.
 19. Theprocess according to claim 16, wherein the in situ combustion propagatesthrough the mobilized zone and through the mobile fluid zone.
 20. Theprocess according to claim 1 wherein the mobile fluid zone is a waterzone.
 21. The process according to claim 20, wherein the oxidizing gasis injected into the mobilized zone.
 22. The process according to claim20, wherein the in situ combustion generates steam from water in thewater zone and the generated steam aids in the mobilization ofhydrocarbons in the reservoir.
 23. A process for hydrocarbon recoveryfrom an oil sands reservoir having a gas zone above a bitumen zone, theprocess comprising: utilizing a generally horizontal well pair togenerate, through steam-assisted gravity drainage, a steam chamber inthe bitumen zone that is in gaseous communication with the gas zone,wherein the generally horizontal well pair comprises: a generallyhorizontal segment of a hydrocarbon production well, and a generallyhorizontal segment of a steam injection well; injecting an oxidizing gasinto the gas zone through an oxidizing gas injection well including anoxidizing gas injection segment, the oxidizing gas supporting in situcombustion in the reservoir and the in situ combustion propagating atleast in the steam chamber; recovering hydrocarbons mobilized by the insitu combustion using the hydrocarbon production well; and producingcombustion gas through the steam injection well; the generallyhorizontal segment of the steam injection well being disposed generallyparallel to and spaced vertically above the horizontal segment of thehydrocarbon production well, and the injection segment of the oxidizinggas injection well being spaced generally above the segment of thehydrocarbon production well and generally above the segment of the steaminjection well.
 24. A process for hydrocarbon recovery from an oil sandsreservoir having a water zone above a bitumen zone, the processcomprising: generating, in the bitumen zone and through steam-assistedgravity drainage, a steam chamber in the bitumen zone that is in fluidcommunication with the water zone; injecting an oxidizing gas through anoxidizing gas injection well into the steam chamber to support in situcombustion in the reservoir and the in situ combustion propagating atleast in the steam chamber; generating steam by heating water in thewater zone through the in situ combustion, the generated steam aiding inmobilizing hydrocarbons in the reservoir; and recovering hydrocarbonsmobilized by the in situ combustion using a hydrocarbon production wellthat is in fluid communication with the water zone and the steamchamber.